Relative permeability curves indicate increasing rock water wetness, higher K ro and lower S or as we proceed from secondary brine flooding to secondary slug of ionic solution flooding to secondary continuous ionic solution flooding.
The findings indicate promising results for ionic solution flooding in secondary mode at irreducible water saturation (S wirr).
This increase can be a reason for increasing oil recovery during flooding test by nanosuspension in comparison with polymer solution flooding.
Ultimate recovery obtained is higher than that obtained with combined secondary brine flooding followed by tertiary ionic solution flooding at residual oil saturation (S or).
Brine and/or ionic solution flooding were conducted in secondary and/or tertiary modes and oil recovery and end point saturations were determined.
Rock water content affects recovery efficiency indicating higher oil recovery for secondary brine and tertiary ionic solution flooding at low S wirr.
Relative permeability curves constructed for the above runs (Fig. 11) indicate increasing rock water wetness, higher oil relative permeability (K ro) and lower S or as we proceed from secondary brine flooding to continuous secondary ionic solution flooding.
Secondary ionic solution flooding runs provided a much higher ultimate recovery of 63 and 70%% OOIP for slug and continuous ionic solution injection, respectively, indicating the efficiency of ionic solution injection in secondary mode at initial oil saturation.
The higher ultimate recovery for the secondary ionic solution flooding can be attributed to the lower water content of the sample rocks and hence the less dilution of the ionic solution within the porous medium.
Sagir et al. (2014c, d) conducted pure CO2 injection after surfactant solution flooding to mimic FAWAG with a new CO2-soluble surfactant using Berea cores, during which a mobility reduction factor of 3.1 was achieved.
